Energy valuations in Houston and Dallas compared, reserves and contracts

What to take away

Houston oilfield services versus Dallas midstream: two different pricing bases

Houston runs on oilfield services and upstream. Dallas runs on midstream and pipeline. The two cities price assets on different numbers, and a buyer who crosses between them usually misprices the first offer.

Named Houston oilfield services operators include Halliburton, SLB and Baker Hughes. Named Dallas midstream operators include Energy Transfer and EnLink Midstream. Houston midstream includes Enterprise Products Partners, Kinder Morgan and Targa Resources.

An oilfield services company in Houston is priced on revenue quality and fleet condition. A pressure pumping fleet, a drilling rig contract or a wireline spread is worth what its next contract pays and what it costs to keep running. EBITDA multiples dominate.

A Dallas midstream company is priced on contracted cash flow. Gathering lines, processing plants and intrastate pipelines earn fees, not commodity prices, when the contracts are structured that way. Backlog and contract life dominate.

Typical negotiated multiples in Texas energy deals are 4.0x to 6.5x EBITDA for oilfield services and 8.0x to 11.0x EBITDA for fee-based midstream. These are typical ranges, not a published index.

The distinction matters because the same EBITDA number can support two different multiples. A services company with one customer and no backlog is riskier than a midstream operator with fifteen years of take-or-pay contracts. Buyers pay for certainty.

Houston also holds the headquarters of many public exploration and production companies. That proximity gives services owners access to buyers who understand the assets. Dallas holds midstream sponsors and private equity funds that treat pipeline systems as long-duration infrastructure.

For a seller, the practical question is which buyer pool will pay more. A Houston strategic buyer may pay for equipment and crews. A Dallas financial buyer may pay for contracted revenue. Run both sets of numbers before choosing a process.

This is where a disciplined valuation methods framework pays off. Start from the earnings definition each buyer uses, then apply the multiple that fits that buyer's model.

Proved reserves and SEC reserve reporting rules

Proved reserves are the quantities a company can reasonably expect to recover from known reservoirs under existing economic and operating conditions. The definition comes from SEC reserve reporting rules, and it drives upstream value more than any other single figure.

Public companies must disclose proved reserves in filings. Private companies do not, but buyers still ask for a reserve report prepared to the same standard. The reason is simple: a reserve report converts geology into a number that can be discounted.

Three categories matter. Proved developed producing reserves are already flowing. Proved developed non-producing reserves are drilled but not yet on line. Proved undeveloped reserves are booked but need capital to produce. Each carries a different risk and a different discount rate.

SEC reserve reporting rules require a price deck based on the average price during the reporting period, held flat except for contractual escalations. That rule removes management's price forecast from the reserve number. Buyers then apply their own deck on top.

Reserve reports are often prepared in Aries, PHDwin or ComboCurve. SEC Regulation S-X Rule 4-10 sets the standardized measure and PV-10 at a 10 percent discount rate. FASB ASC 932 covers oil and gas disclosures.

The result is a two-layer valuation. The reserve report gives a standardized measure. The buyer's deck gives a market view. The gap between them is often where the negotiation happens.

Reserve reports also carry a decommissioning liability. Plugging and abandonment obligations attach to the wells, and buyers deduct their present value from the asset value. A seller who ignores this in the asking price will lose it in the letter of intent.

For a private seller, commissioning a reserve report before going to market is usually worth the cost. It shortens due diligence and gives the buyer fewer reasons to discount.

Backlog, contracts and take-or-pay terms in midstream valuation

Midstream valuation rests on contracts, not reserves. A gathering system with a twenty-year fee-based contract is a different asset from a system that depends on spot volumes.

Backlog is the contracted revenue not yet recognized. For an oilfield services company, backlog is the value of signed contracts and purchase orders. For a midstream company, backlog is the remaining life of transportation, gathering and processing agreements.

Take-or-pay terms shift volume risk from the midstream operator to the shipper. The shipper pays whether or not it moves the gas. That structure raises the multiple because the cash flow is closer to a utility than to a commodity business.

Fee-based contracts without take-or-pay still earn revenue per unit moved. Volume risk remains with the operator. Buyers price that risk through a lower multiple or a higher discount rate.

Contract concentration is the other variable. A midstream system with one shipper accounting for most throughput is priced like a single-customer business. Diversified shippers support a higher multiple.

Contract term matters too. A contract with three years left is worth less than one with fifteen, even at the same fee. Buyers model the recontracting risk at the end of the term.

A worked example shows the mechanics. Suppose a Dallas gathering system generates $10 million in annual fee-based EBITDA with twelve years of weighted average contract life. A buyer applies a 9x multiple for contracted, fee-based cash flow, arriving at $90 million enterprise value.

If the contracts were spot-exposed, the same EBITDA might draw 6x, or $60 million. The $30 million gap is the value of the contract structure.

A valuation methods comparison across the market, income and asset approaches will show which one the contract structure supports. Midstream usually favors the income approach.

Commodity cycles and how they move the multiple

Commodity cycles move the multiple before they move the cash flow. When West Texas Intermediate rises, buyers bid up oilfield services assets on expectations of higher activity. When it falls, the same assets lose value faster than revenue declines.

The multiple is a forecast in disguise. A 6x EBITDA multiple on a services company implies the buyer expects earnings to persist. In a downcycle, buyers assume earnings will fall, so they apply a lower multiple to the same trailing number.

Midstream is less cyclical but not immune. Fee-based contracts cushion the fall. Volume-based contracts do not. A Dallas midstream operator with take-or-pay contracts may hold its multiple through a downturn while a Houston services company loses two turns.

Cycles also change the buyer mix. In an upcycle, strategics and private equity compete, and prices rise. In a downcycle, distressed buyers and asset strippers enter, and prices fall.

Sellers who can wait often do better. But waiting carries its own cost, including maintenance capex and key employee attrition. The decision is a timing call, not a valuation call.

Buyers should stress-test the price deck. A model that only works at $80 oil is not a model, it is a bet. Run the same asset at a low deck and see whether the debt still services.

This is where valuation methods mistakes often appear. The base figure is a mid-cycle number, but the multiple is an upcycle multiple. The two do not belong together.

EIA data used to build the price deck

The price deck is the set of commodity prices a buyer uses to project revenue. Most Texas energy buyers build it from EIA data, not from their own forecasts.

The EIA publishes petroleum data, including spot prices for crude oil and refined products. Houston energy valuations use these series to set the oil price assumption in the model. Petroleum data covers the crude benchmarks that drive Texas upstream and services revenue.

EIA's Short-Term Energy Outlook and Annual Energy Outlook provide the price projections many buyers use.

Natural gas data matters for Dallas midstream and for gas-weighted reserves. Natural gas data includes Henry Hub spot prices and storage levels, which drive gathering and processing economics.

Sector-wide context comes from total energy data. Total energy data shows consumption, production and price trends across the whole energy economy, useful when a buyer wants to frame a Texas asset against national demand.

Definitions matter as much as numbers. The EIA's frequently asked questions explain how the agency defines reserves, production and prices, which keeps the deck consistent with the reserve report.

A practical deck uses a strip price for the first two years and a flat long-run price thereafter. The flat price should reflect a mid-cycle view, not the current spot price. Buyers who use spot as the long-run price overpay at the top and underpay at the bottom.

The deck should be documented. A buyer who can show the source of each price assumption has a stronger position in negotiation and a cleaner file for lenders.

Discount rates and terminal value in energy DCFs

A discounted cash flow model converts a price deck and a production or contract schedule into a present value. The discount rate reflects the risk of the cash flows. The terminal value captures everything after the forecast period.

For proved developed producing reserves, discount rates in the low double digits are common. For proved undeveloped reserves, the rate rises because the cash flows depend on future capital. For midstream with take-or-pay contracts, the rate falls toward high single digits.

The discount rate is not a single number pulled from a table. It reflects the buyer's cost of capital, the asset's risk profile and the debt capacity of the cash flows. A buyer with cheap debt can pay more for the same asset.

Terminal value is where most energy DCFs go wrong. A model that assumes production continues at the final year's rate forever will overvalue a depleting asset. A model that assumes a midstream contract renews at the same fee forever will overvalue a recontracting risk.

The safer approach is to build terminal value from the asset's own limits. For upstream, that means a declining production profile to the end of reserves. For midstream, that means a contract-by-contract roll-off with a recontracting assumption.

A sensitivity table helps. Run the model at three discount rates and three terminal assumptions, and see how much of the value sits in the terminal period. If most of the value is terminal, the model is fragile.

Buyers should also check the discount rate against the multiple. A 10x multiple on stable cash flow implies a discount rate near 10 percent. If the DCF uses 15 percent and the multiple implies 10, one of them is wrong.

Our guide to the best business brokers services 2027 shows how earnouts and rollover equity can bridge a gap between a seller's DCF and a buyer's. In energy, earnouts tied to production or contract renewals are common.

What buyers deduct for decommissioning and capex

Headline enterprise value is not the number the seller receives. Buyers deduct decommissioning liabilities, maintenance capex and other obligations before arriving at equity value.

Decommissioning covers plugging and abandonment of wells and removal of facilities. In Texas, the Railroad Commission regulates these obligations, and buyers estimate the cost per well and discount it to present value.

Maintenance capex is the spending required to keep production or throughput flat. For oilfield services, it is fleet maintenance and recertification. For midstream, it is pipeline integrity, compressor overhauls and regulatory compliance.

Growth capex is treated differently. A buyer may fund it from the asset's own cash flow or require the seller to complete projects before closing. The treatment affects the purchase price.

A table shows the common deductions and how they affect value.

Working capital deserves attention. Energy businesses carry receivables, inventory and prepaid expenses. A buyer expects a normalized level of working capital at closing, and any shortfall reduces the cash paid.

A material acquisition or disposition by a public buyer may require a current report on Form 8-K within four business days. That filing clock affects how quickly a public company can move on a Texas energy deal.

Sellers should model these deductions before setting an asking price. A $100 million enterprise value can become $80 million in cash after decommissioning, capex and working capital adjustments.

A numbered sequence helps a seller prepare.

A checklist for buyers covers the same ground from the other side.

Common questions